Wellbore real-time monitoring and analysis of fracture contribution

ABSTRACT

Methods and apparatus are provided for calculating production of each of a plurality of fractured intervals (or fractures) and monitoring changes in the fracture contribution with time. Such real-time monitoring and analysis may be performed by combining temperature distribution (and pressure) measurements, a real-time surface multiphase flow measurement, and an inflow model for each fractured interval (or fracture). In this manner, the industry may be able to understand the behavior of fractures and, in turn, optimize the number of stages (i.e., fractured intervals), the number of fractures, and the spacing between fractures and stages.

CLAIM OF PRIORITY UNDER 35 U.S.C. §119

The present application claims benefit of U.S. Provisional PatentApplication No. 61/611,924, filed Mar. 16, 2012, which is hereinincorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to hydrocarbonproduction and, more particularly, to determining the individualcontribution of fractured intervals (or fractures) in time.

2. Description of the Related Art

Various tools may be used in order to measure the contribution of thefractures within wellbores. Different services companies may runproduction logging tools, and chemical tracers may also be used todetermine the fracture contribution. However, these measurements mayonly provide a snapshot of what is happening at the moment themeasurements are performed, and may change with time because conditionswithin the wellbore are transient.

SUMMARY OF THE INVENTION

Embodiments of the invention generally relate to allocating productionof each of a plurality of fractured intervals (or fractures). Thisallocation may be performed by combining temperature distribution (andpressure) measurements, a real-time surface multiphase flow measurement,and an inflow model for each fractured interval (or fracture).

One embodiment of the invention is a method for determining productionof hydrocarbons. The method generally includes determining a temperaturedistribution associated with a plurality of fractured intervals orfractures disposed along a well; measuring a total flow rate for thewell; modeling an inflow rate for each of the plurality of fracturedintervals or fractures; and allocating production of each of theplurality of fractured intervals or fractures based on the temperaturedistribution, the total flow rate, and the inflow rates.

Another embodiment of the invention provides a system for determiningproduction of hydrocarbons. The system generally includes a temperaturesensing device configured to determine a temperature distributionassociated with a plurality of fractured intervals or fractures disposedalong a well, a flowmeter configured to measure a total flow rate forthe well, and a processing unit. The processing unit is typicallyconfigured to model an inflow rate for each of the plurality offractured intervals or fractures and to allocate production of each ofthe plurality of fractured intervals or fractures based on thetemperature distribution, the total flow rate, and the inflow rates.

Yet another embodiment of the invention provides a system fordetermining production hydrocarbons. The system generally includes meansfor determining a temperature distribution associated with a pluralityof fractured intervals or fractures disposed along a well; means formeasuring a total flow rate for the well; means for modeling an inflowrate for each of the plurality of fractured intervals or fractures; andmeans for allocating production of each of the plurality of fracturedintervals or fractures based on the temperature distribution, the totalflow rate, and the inflow rates.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 is a conceptual diagram of a system for producing hydrocarbons,the system having a pipe inside a casing and downhole tools positionedat various locations along the pipe, in accordance with an embodiment ofthe invention.

FIG. 2 illustrates an ideal reservoir model with multiple fractures, inaccordance with an embodiment of the invention.

FIG. 3 illustrates hydrocarbon production allocation from multiplewells, in accordance with an embodiment of the invention.

FIG. 4 illustrates hydrocarbon production allocation from a horizontalwell with multiple fractured intervals, in accordance with an embodimentof the invention.

FIG. 5 is a flow diagram of example operations for allocatinghydrocarbon production to multiple fractured intervals (or fractures),in accordance with an embodiment of the invention.

FIG. 6 illustrates a workflow for identifying and calculating thecontribution of each fractured interval (or fracture), in accordancewith an embodiment of the invention.

FIG. 7 illustrates an example plot of gas production versus number ofcontributing fractures, in accordance with an embodiment of theinvention.

DETAILED DESCRIPTION

Embodiments of the invention provide techniques and apparatus forcalculating production of each of a plurality of fractured intervals (orfractures) and monitoring changes in the fracture contribution withtime. Such real-time monitoring and analysis may be based on acombination of different measurements in the wellbore, on the surface,and from a mathematical model, as described below. In this manner, theindustry may be able to understand the behavior of fractures and, inturn, optimize the number of stages (i.e., fractured intervals), thenumber of fractures, and the spacing between fractures and stages.

Referring to FIG. 1, there is shown a hydrocarbon production system 100containing one or more production pipes 102 (also known as productiontubing) that may extend downward through a casing 104 to one or morehydrocarbon sources 106 (e.g., reservoirs). An annulus 108 may existbetween the pipe 102 and the casing 104. Each production pipe 102 mayinclude one or more lateral sections (e.g., created by horizontaldrilling) that branch off to access different hydrocarbon sources 106 ordifferent areas of the same hydrocarbon source 106. The fluid mixturemay flow from sources 106 to the well completion through the productionpipes 102, as indicated by fluid flow 130. The production pipe 102 mayinclude one or more tools 122 for performing various tasks (e.g.,sensing parameters such as pressure or temperature) in, on, or adjacenta pipe or other conduit as the fluid mixtures flow through theproduction pipes 102. The tools 122 may be any type of downhole device,such as a flow control device (e.g., a valve), a sensor (e.g., apressure, temperature or fluid flow sensor) or other instrument, anactuator (e.g., a solenoid), a data storage device (e.g., a programmablememory), a communication device (e.g., a transmitter or a receiver),etc.

Each tool 122 may be incorporated into an existing section of productionpipe 102 or may be incorporated into a specific pipe section that isinserted in line with the production pipe 102. The distributed scheme oftools 122 shown in FIG. 1 may permit an operator of the system 100 todetermine, for example, the level of depletion of the hydrocarbonreservoir. This information may permit the operator to monitor andintelligently control production of the hydrocarbon reservoir.

Advances in directional drilling (e.g., horizontal drilling as shown inFIG. 1) and reservoir stimulation techniques have dramatically increasedgas production from wells drilled in shale reservoirs that wereconsidered uneconomical not too long ago. In spite of many advances inunderstanding the behavior of the production of this type of reservoir,many unknowns remain, such as determining the optimal length ofhorizontal sections, how many stages, and determining how many fracturesare optimal. Particularly, it is difficult to predict productivity fromcores, logs, drillstem tests (DSTs), or early well-productionperformance. Drainage volumes are uncertain, and well spacing is basedon trial and error methods.

The use of microseismic and production logs has helped in the fractureevaluation to determine the drainage volume and fracture inflow.Microseismic can provide useful information on the development offracture symmetry, half-length, azimuth, width and height, and theirdependence on the treatment parameters and reservoir characteristics.Additionally, these fracture geometries in conjunction with othermeasured or calculated parameters (e.g., rates, inflow models, etc.) canbe used to better understand fracture modeling and productioncharacteristics.

Review of production logs have indicated that only a percentage of thefractures are contributing to the production, and until now, onlysnapshots of the fracture contributions have been made. However,considering that this is a transient system (where fracturecontributions typically change with time, typically for the first 15 to20 months of production), a snapshot measurement is not sufficient tounderstand the behavior of the fractures and their contribution overtime.

Accordingly, what is needed are techniques and apparatus forestablishing which fractures (or at least which fractured intervals) arecontributing and how much.

Due to the transient behavior, an ideal system would offer continuous,permanent, and real-time monitoring on key variables like productionrates, pressure and temperature in an effort to determine the fracturecontributions. Procedures that integrate different types of measurementsand calculations in “real time” may help to find and understand thebehavior of the fractures and to optimize the number of stages,fractures, and spacing.

Embodiments of the invention provide methods and apparatus to optimize,or at least increase, the production of horizontal fractured wells inshale reservoirs, for example. By integrating different types ofreal-time measurements, methods described herein enable the optimizationof the number of fractures, the spacing of fractures, and the length ofthe horizontal section by determining the contribution of the fracturestages (or the fractures) over time.

One way to solve this problem might be the installation of downholeflowmeters in each fracture stage. However, this can be a challengeoperationally and may also be very costly and risky.

Instead, considering the very low permeability of shale reservoirs (onthe order of nanodarcys), it can be established that a reservoir iscreated only after fracturing. If the spacing between fractures iscorrect (such that the fractures do not interfere with one another), theproduction allocation of each fracture stage (or fracture) may becalculated in an analogous way to that performed in a traditional field,where the total production rates are allocated to each production wellusing well testing measurements, done periodically with dailymeasurement information like wellhead pressure. In this particular case,by combining permanent downhole measurement of temperature (and one ormore pressure measurements at the heel and the toe of the wellbore, forexample), permanent wellhead flow measurement of the different phases,and a mathematical transient model of the production rates of eachfracture, an acceptable production allocation can be made as a functionof time. Because the system is transient, such allocation may beperformed on a real-time basis.

In scenarios where the number of fractures is large, the idealizedsystem 200 shown in FIG. 2 may be used to model the reservoir. In FIG.2, multiple fractures 204, 206 are represented as spaced along andtransverse to the horizontal well trajectory 202. Assuming fracturingconditions were the same, the length and width of each fracture in thefracture stage may be considered equal. These parallel fractures areformed in an area (e.g., a shale reservoir) with essentially zeropermeability (as illustrated in the region 212 unshaded in FIG. 2),thereby forming a region 214 of modified permeability (shaded in FIG.2), essentially creating a reservoir where none existed before. Althoughany number of fractures (N_(Nfrac)) may be formed with any spacingtherebetween, five fractures are illustrated in the fracture stage ofFIG. 2 (two external fractures 204 and three internal fractures 206)with equal fracture spacing. The fracture stage is defined by confiningexternal boundaries 210. FIG. 2 shows that external fractures 204 areconfined by virtual no-flow boundaries 208, which force the externalfractures to have the same behavior as the internal fractures 206, andpure linear flow initially occurs. In shale gas reservoirs of nanodarcypermeability, pure linear flow opposite the fracture faces occurs forvery long times.

The concept of Stimulated Reservoir Volume (SRV) is based on the premisethat negligible flow occurs from beyond the fracture tips. The reservoiris created by the fracturing, and the reservoir size is limited by thelength of the main fracture. Production performance from the fracturedreservoir may be based on the SRV, the fracture spacing, and thefracture conductivity.

The near-wellbore temperature distribution yielded by distributedtemperature sensing (DTS) or multi-point or array temperature sensing(ATS) may be used to determine the relative amount of fluid that eachperforation interval contributes. If this information is combined withone or more pressure measurements and a real-time surface multiphaseflow measurement in conjunction with an inflow model for each fracturedinterval, a production allocation may be calculated for each fracture.This approach is analogous to a traditional well allocation where adaily aggregated measurement at the production plant is back-allocatedto each well based on wellhead measurements like pressure, temperature,and well performance. The description below provides details on the useof these technologies to analyze the fracture behavior in horizontalwells in shale reservoirs, for example.

FIG. 3 illustrates a multi-well system 300 in an oil/gas productionfield, in which hydrocarbon production may be allocated to each of thewells. In this allocation process, periodical (e.g., 15 days to weeks ormonths) production well tests are performed on each individual well, anddaily (or in some cases, every few hours) pressure (P) and/ortemperature (T) measurements at or near the wellhead 302 of each wellare registered. The produced fluids from each well may be collected at amanifold and then separated by a separator 310 into oil, gas, and water.Daily (or in some cases, every few hours or minutes) total flow rates ofoil (Qo), gas (Qg), and water (Qw) may be measured. With the productionwell tests, using nodal analysis techniques, the well performance (P vs.Q relation) for each well at the wellhead 302 is calculated. The use ofthis wellhead performance with frequent wellhead pressure measurementsallows the flow rates of each individual well to be determined.

Ideally, the addition of all these individual well flow rates is thetotal production of the field, but for various reasons (e.g., wellperformance of each well can change over time), there is a differencebetween these values. To eliminate this difference, an allocation factor(K) is found using the relationship between the total flow rate (Qt)measured and the sum of the individual well flow rates (ΣQi) and may besubsequently used.

FIG. 4 illustrates a system 400 for allocating hydrocarbon produced froma horizontal well with multiple fractured intervals 402 along ahorizontal well, in accordance with an embodiment of the invention.Although seven fractured intervals 402, each with five fractures 404,are shown in FIG. 4, any number of fractured intervals and any number offractures per interval may be used. The system 400 also includes amultiphase real-time flowmeter 406 and a DTS cable 408 disposeddownhole. The system may also include one or more sensors 410 formeasuring pressure (P) and/or temperature (T), which may be disposedanywhere in the wellbore, such as in the vertical section as shown. Themultiphase flowmeter 406 may be installed at or adjacent the wellhead orwithin the wellbore and, for some embodiments, may be an opticalflowmeter (e.g., an optical downhole flowmeter). The DTS cable 408 maybe installed adjacent the casing 104, as shown in FIG. 4.

Drawing an analogy to the multi-well system 300 of FIG. 3, each stage(i.e., fractured interval 402) in FIG. 4 is akin to a producing well.With the help of the variation of temperature and a transient inflowmodel, it is possible to calculate the production of each stage at anytime. In fact, if the temperature variation is high enough todistinguish between fractures 404, it may also be possible to allocatethe production of each particular fracture.

The analogy between production allocation for individual wells andstages (or fractures) is possible (i.e., each stage or fracture may beconsidered as an individual contributor to production) because, due tothe low permeability of this type of reservoir (as described above withrespect to FIG. 2), the communication between stages, and even betweenfractures, is negligible. The main characteristics of the fractures(e.g., length and width) may be considered equal in each stage, assumingfracturing conditions were the same. The inflow rate of each fracturewill be computed by an analytical transient model and combined with thechange in temperature (as determined by the DTS cable 408, for example)at each stage referenced to an initial condition prior to fracturing. Inconjunction with the total flow rate (Qt) measured by the multiphaseflowmeter 406, a production allocation for each stage (Qsi) (or eachfracture) will be performed.

FIG. 5 is a flow diagram of example operations 500 for determining thecontribution to hydrocarbon production of each fractured interval (oreach fracture). The operations 500 may begin, at 502, by determining atemperature distribution associated with a plurality of fracturedintervals or fractures disposed along a well. The temperaturedistribution may be determined by performing at least one of distributedtemperature sensing (DTS) or array temperature sensing (ATS). Theplurality of fractured intervals or fractures may be located in a shalereservoir, for example.

At 504, a total flow rate of a fluid (or any combination of fluids)produced by the well (i.e., the produced hydrocarbons) is measured. Thetotal flow rate may be a total gas flow rate or a total oil flow rate,for example. For some embodiments, the total flow rate may be measuredusing a flowmeter disposed at the surface. For example, the flowmetermay be disposed at or adjacent a wellhead of the well.

An inflow rate is modeled at 506 for each of the plurality of fracturedintervals or fractures. The inflow rate may be an inflow gas rate or aninflow oil rate, for example.

At 508, production of each of the plurality of fractured intervals orfractures is allocated based on the temperature distribution, the totalflow rate, and the inflow rates. For some embodiments, allocating theproduction at 508 may include: (1) determining a first temperature valueT₀ at a first time t₀ (e.g., before production starts) for each of theplurality of fractured intervals or fractures; (2) determining a secondtemperature value T_(n) at a second time t_(n) (e.g., subsequent to thefirst time t₀) for each of the plurality of fractured intervals orfractures; (3) calculating a delta temperature value (ΔT_(n)=T_(n)−T₀)for the second time t_(n) for each of the plurality of fracturedintervals or fractures by determining a difference between the first andsecond temperature values for each of the plurality of fracturedintervals or fractures; (4) calculating a first ratio (ΔT/Tg)_(n) of thedelta temperature value ΔT_(n) for the second time t_(n) for each of theplurality of fractured intervals or fractures to a geothermaltemperature (Tg) at the second time t_(n) (5) comparing the first ratio(ΔT/Tg)_(n) for the second time t_(n) to a maximum value of the firstratio over all previous times for each of the plurality of fracturedintervals or fractures (6) for each of the plurality of fracturedintervals or fractures, designating the first ratio for the second timet_(n) as the maximum value of the first ratio over all previous times ifthe first ratio for the second time t_(n) is greater than the previouslydesignated maximum value (7) calculating a second ratio(ΔT/Tg)/(ΔT/Tg)max of the first ratio for the second time t_(n) for eachof the plurality of fractured intervals or fractures to the currentlydesignated maximum value of the first ratio over all previous times foreach of the plurality of fractured intervals or fractures; (8)multiplying the second ratio for the second time t_(n) with the modeledinflow rate corresponding to the second time t_(n) for each of theplurality of fractured intervals or fractures; (9) summing results ofthe multiplication for each of the plurality of fractured intervals orfractures; (10) determining an allocation factor (K) by dividing themeasured total flow rate corresponding to the second time t_(n) by thesum; (11) applying the allocation factor (K) to the modeled inflow ratefor each of the plurality of fractured intervals or fractures.

For some embodiments, the operations 500 may also include repeating thedetermining at 502, the measuring at 504, and the modeling at 506 withina period short enough to observe transient behavior of the plurality offractured intervals or fractures. The determining, measuring, and/ormodeling described above may be performed and repeated with any desiredfrequency (at any desired rate or periodicity). For example, thedetermining, measuring, and/or modeling may be performed continuously,hourly, daily, weekly, or with other frequencies.

For some embodiments, the operations 500 may also include determiningone or more pressure measurements for the well. In this case, allocationof the production at 508 may also be based on the pressure measurements.The pressure measurements may be made by one or more pressure sensorslocated downhole, along the horizontal or vertical portion of thewellbore. The pressure sensors may be optical-based pressure sensorshaving one or more fiber Bragg gratings (FBGs) located therein.

FIG. 6 illustrates a workflow 600 for identifying and calculating thecontribution of each fractured interval (or fracture), in accordancewith an embodiment of the invention. For simplicity, the descriptionbelow will focus on production allocation for each fractured interval.The workflow 600 can be easily expanded to production allocation foreach fracture, as long as the temperature variation is high enough todistinguish between fractures.

In the workflow 600, the DTS (or ATS) data 602 is related to thegeothermal gradient value for each stage 402. The cable 408 may besampled with some periodicity to generate the data 602, leading totemperature measurements at certain sampling times (t_(n)). For eachsampling time (t_(n)), the delta temperature (ΔT) between thetemperature at the sampling time and at time t₀ is calculated for eachstage 402. At 604, the ΔT values for each stage are divided by Tg tonormalize the data. For some embodiments, pressure measurements (e.g.,taken by the sensors 410) may be used to ensure accuracy of the ΔTvalues for each stage (e.g., by correlation with the temperaturemeasurements). At 606, a ratio ((ΔT/Tg)/(ΔT/Tg)max) for the samplingtime (t_(n)) is calculated for each stage 402. The ratio for each stageis calculated by dividing the Tg-normalized ΔT value for this particularstage by the maximum Tg-normalized ΔT value over all previous times forthis stage.

The ΔT value at time t₀ is initially assumed to be the maximumTg-normalized ΔT value, so the ratio in this case will be 1. The maximumΔT value is stored for later validation of this assumption.

At 608, inflow transient models are run to generate inflow rates foreach stage 402 (indexed by “i”). The workflow 600 of FIG. 6 generatesinflow gas rates for each stage (Qgfi), but inflow oil rates or both mayalso be used. The inflow transient models either produce the inflowrates at the sampling time (t_(n)) as shown at 610, or interpolation orother techniques are used to determine inflow rates at the sampling timebased on inflow rates produced for other times. At 612, the ratio at thesampling time (t_(n)) for each stage calculated at 606 is multipliedwith the modeled inflow rate for each stage from 610 corresponding tothe sampling time.

As described above, surface multiphase measurements may be made at 614,for example, by the flowmeter 406, to generate one or more total flowrates (Qg, Qo, and/or Qw) for the well. The total flow rates may eitherbe generated at the sampling time (t_(n)) as shown at 616, orinterpolation or other techniques may be used to determine the totalflow rates at sampling time based on measurements taken at other times.

The results of the multiplications at 612 for each of the stages 402 atthe sampling time (t_(n)) may be summed (ΣQ'gfi). At 618, this sum maybe compared to the total gas flow rate (Qg) corresponding to thesampling time (t_(n)).

At the first sampling time (t₀), the ratio for each stage 402 calculatedat 606 is multiplied by the Qgfi at t₀ for each stage at 612, and thesum of all Qgfi values is compared to the Qg corresponding to t₀ at 618.For this time t₀, it is being assumed that all fractures arecontributing at their 100% capacities, unless the ΔT value is zero, inthe case of no contribution. For the next time t₁, the value of ΔT₁ willbe compared to the value of ΔT₀. If ΔT₁ is bigger, then a new maximumvalue is obtained. This new maximum value replaces the previous value,and in this case the contribution of this particular stage will be 100%during this period of time, and the assumption on the previous time stepwas wrong. A new calculation for t₀ will be performed to correct thefirst assumption and similarly at any time that a new maximum value isfound.

The workflow 600, operating on a “real-time” basis, will increase wellproductivity, helping to determine what is the optimal choke size toflow back the well and to have all fractures contributing (or to findout which fractures do not contribute at all). After this procedure isperformed on different wells with a different number of stages and/orfractures, a normalized graph of production versus a number ofcontributing stages and/or fractures can be obtained and, based on theseresults, an optimal number of stages and/or fractures may be determined.A good relationship is expected of production versus number ofcontributing fractures, more consistent than the plot 700 of gasproduction versus number of contributing fractures shown in FIG. 7 (fromModeland N. et al., “Stimulation's Influence on Production in theHaynesville Shale: A Playwide Examination of Fracture-TreatmentVariables that Show Effect on Production,” SPE 148940 presented atCanadian Unconventional Resources Conference, 15-17 November 2011,Alberta, Canada).

As described above, the near-wellbore temperature distribution yieldedby distributed temperature sensing (DTS) or multi-point or arraytemperature sensing (ATS) may be used to determine the relative amountof fluid that each perforation interval contributes. If this informationis combined with a real-time surface multiphase flow measurement inconjunction with an inflow model for each fractured interval (and one ormore pressure measurements), a production allocation may be calculatedfor each fractured interval or fracture. This approach is analogous to atraditional well allocation where a daily aggregated measurement at theproduction plant is back-allocated to each well based on wellheadmeasurements like pressure, temperature, and well performance.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. A method for determining production of hydrocarbons, comprising:determining a temperature distribution associated with a plurality offractured intervals or fractures disposed along a well; measuring atotal flow rate for the well; modeling an inflow rate for each of theplurality of fractured intervals or fractures; and allocating productionof each of the plurality of fractured intervals or fractures based onthe temperature distribution, the total flow rate, and the inflow rates.2. The method of claim 1, further comprising repeating the determining,the measuring, and the modeling within a period short enough to observetransient behavior of the plurality of fractured intervals or fractures.3. The method of claim 1, further comprising determining one or morepressure measurements for the well, wherein allocating the production isfurther based on the pressure measurements.
 4. The method of claim 1,wherein determining the temperature distribution comprises performing atleast one of distributed temperature sensing (DTS) or array temperaturesensing (ATS).
 5. The method of claim 1, wherein the measuring comprisesmeasuring the total flow rate using a multiphase flowmeter.
 6. Themethod of claim 1, wherein at least one of the determining, themeasuring, or the modeling is performed daily.
 7. The method of claim 1,wherein at least one of the determining, the measuring, or the modelingis performed continuously.
 8. The method of claim 1, wherein allocatingthe production comprises: determining a first temperature value at afirst time for each of the plurality of fractured intervals orfractures; determining a second temperature value at a second time foreach of the plurality of fractured intervals or fractures; calculating adelta temperature value for the second time for each of the plurality offractured intervals or fractures by determining a difference between thefirst and second temperature values for each of the plurality offractured intervals or fractures; calculating a first ratio of the deltatemperature value for the second time for each of the plurality offractured intervals or fractures to a geothermal temperature; comparingthe first ratio for the second time to a maximum value of the firstratio over all previous times for each of the plurality of fracturedintervals or fractures; for each of the plurality of fractured intervalsor fractures, designating the first ratio for the second time as themaximum value of the first ratio over all previous times if the firstratio for the second time is greater than a previously designatedmaximum value; for each of the plurality of fractured intervals orfractures, calculating a second ratio of the first ratio for the secondtime to a currently designated maximum value of the first ratio over allprevious times; multiplying the second ratio for the second time withthe modeled inflow rate corresponding to the second time for each of theplurality of fractured intervals or fractures; summing results of themultiplication for each of the plurality of fractured intervals orfractures; and determining an allocation factor by dividing the measuredtotal flow rate corresponding to the second time by the sum.
 9. Themethod of claim 8, wherein the first time occurs before the hydrocarbonsare produced.
 10. The method of claim 8, further comprising applying theallocation factor to the modeled inflow rate for each of the pluralityof fractured intervals or fractures.
 11. The method of claim 1, whereinthe total flow rate comprises a total gas flow rate and wherein theinflow rates comprise inflow gas rates.
 12. The method of claim 1,wherein the plurality of fractured intervals or fractures is located ina shale reservoir.
 13. A system for determining production ofhydrocarbons, comprising: a temperature sensing device configured todetermine a temperature distribution associated with a plurality offractured intervals or fractures disposed along a well; a flowmeterconfigured to measure a total flow rate for the well; and a processingunit configured to: model an inflow rate for each of the plurality offractured intervals or fractures; and allocate production of each of theplurality of fractured intervals or fractures based on the temperaturedistribution, the total flow rate, and the inflow rates.
 14. The systemof claim 13, wherein the plurality of fractured intervals or fracturesis located in a shale reservoir.
 15. The system of claim 13, furthercomprising a pressure sensor configured to determine one or morepressure measurements for the well, wherein the processing unit isconfigured to allocate the production further based on the pressuremeasurements.
 16. The system of claim 13, wherein the processing unit isconfigured to allocate the production by: determining a firsttemperature value at a first time for each of the plurality of fracturedintervals or fractures; determining a second temperature value at asecond time for each of the plurality of fractured intervals orfractures; calculating a delta temperature value for the second time foreach of the plurality of fractured intervals or fractures by determininga difference between the first and second temperature values for each ofthe plurality of fractured intervals or fractures; calculating a firstratio of the delta temperature value for the second time for each of theplurality of fractured intervals or fractures to a geothermaltemperature; comparing the first ratio for the second time to a maximumvalue of the first ratio over all previous times for each of theplurality of fractured intervals or fractures; for each of the pluralityof fractured intervals or fractures, designating the first ratio for thesecond time as the maximum value of the first ratio over all previoustimes if the first ratio for the second time is greater than apreviously designated maximum value; for each of the plurality offractured intervals or fractures, calculating a second ratio of thefirst ratio for the second time to a currently designated maximum valueof the first ratio over all previous times; multiplying the second ratiofor the second time with the modeled inflow rate corresponding to thesecond time for each of the plurality of fractured intervals orfractures; summing results of the multiplication for each of theplurality of fractured intervals or fractures; and determining anallocation factor by dividing the measured total flow rate correspondingto the second time by the sum.
 17. The system of claim 16, wherein theprocessing unit is further configured to apply the allocation factor tothe modeled inflow rate for each of the plurality of fractured intervalsor fractures.
 18. The system of claim 13, wherein the temperaturesensing device comprises a distributed temperature sensing (DTS) deviceor an array temperature sensing (ATS) device.
 19. The system of claim13, wherein the total flow rate comprises a total gas flow rate andwherein the inflow rates comprise inflow gas rates.
 20. A system fordetermining production of hydrocarbons, comprising: means fordetermining a temperature distribution associated with a plurality offractured intervals or fractures disposed along a well; means formeasuring a total flow rate for the well; means for modeling an inflowrate for each of the plurality of fractured intervals or fractures; andmeans for allocating production of each of the plurality of fracturedintervals or fractures based on the temperature distribution, the totalflow rate, and the inflow rates.